Good day, my name is Lisa, and I will be your conference operator. At this time, I would like to welcome everyone to the SM Energy Third Quarter Earnings Conference Call. [Operator Instructions] This time, I would now like to turn the call over to your host, Mr. David Copeland. Please go ahead.

Thank you, Lisa. Good morning to all of you joining us by phone and online for SM Energy's Third Quarter 2012 Earnings Conference Call and Operations Update. Before we start, I'd like to advise you that we will be making forward-looking statements during this call about our plans, expectations and assumptions regarding our future performance. These statements involve risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements. For a discussion of these risks, you should refer to the cautionary information about forward-looking statements in our press release from yesterday afternoon, the presentation posted on our website for this call and the Risk Factors section in our Form 10-K filed earlier this year and the Form 10-Q that was filed this morning. We'll also discuss certain non-GAAP financial measures that we believe are useful in evaluating our performance. Reconciliation of those measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are described in our earnings press release from yesterday. Additionally, we may use the terms probable, possible and 3P reserves and estimated ultimate recovery or EUR on this call. You should read the Cautionary Language page in our slide presentation for an important discussion of these terms and the special risks and other considerations associated with these non-proved reserve metrics. Company officials on the call this morning are Tony Best, our Chief Executive Officer; Jay Ottoson, Our President and Chief Operating Officer; Wade Pursell, Executive Vice President and Chief Financial Officer; Brent Collins, Senior Director of Planning and Investor Relations; and myself, the company's Senior Vice President and General Counsel and Corporate Secretary. With that, I'll turn the call over to Tony.

Thank you, David. Good morning, everyone, and thank you for joining us this morning for our third quarter 2012 earnings call. I'll make a few introductory remarks, and then Wade and Jay will provide their respective financial and operational reviews. We'll be referring to slides this morning from the presentation that was posted on our website last evening. And my comments will begin with Slide 3. We reported record quarterly productions of 57 BCF equivalent or $9.5 million barrels of oil equivalent, which is a 13% increase in total production from the previous quarter. And Jay will elaborate in his operational update. We started up a number of additional gathering system facilities in our operated Eagle Ford shale program in the third quarter, allowing production to grow substantially during that quarter. Lastly, we have increased our full year production guidance with a range of 215.5 to 218.5 BCF equivalent from our previous guidance range of 210 to 217 BCF equivalent. In all, it was a strong quarter for the company and in addition to our production growth, we met or beat guidance on all metrics. I'll now turn the call over to Wade for his financial update.

Thank you, Tony, good morning. I'll start on Slide 5 with a recap of our quarterly performance. Adjusted net in income for the quarter was $9.7 million or $0.14 per diluted share, and our EBITDAX for the quarter came in at $261 million. Both of which, I think, were well above consensus estimates. With regard to our performance against guidance, our average daily production of 620 million cubic feet equivalent per day was 6% above the midpoint of our production guidance range of 565 to 603. This outperformance was largely driven by the growth in our Eagle Ford Shale program which Jay will touch on later on all. On the cost side, you can see on the slide, we came in below the low end of guidance on most metrics with the remaining metrics meeting our guidance range. I'll cover a few highlights. LOE was below the low end of the range due primarily to the operated Eagle Ford Shale program, cost saving initiatives and the installation of water recycling facility have lowered cost below our earlier expectations. Transportation expense was lower than expected due to anticipated additional fees resulting to oil transportation and compression, which have yet to occur as the systems were not placed in service during the quarter. From our production tax standpoint, we have lower-than-guided production taxes due primarily to severance tax incentives for deep gas wells in the Texas portion of our Haynesville Shale program. Lastly, G&A overall was lower than guided due primarily to greater production volumes. Moving to Slide 6, I'll quickly discuss our financial position. The third quarter was pretty quiet with regard to financing as our capital structure remained unchanged with no new debt issuances or other financings. Our debt-to-book cap rose slightly, ending the quarter 47% and our debt to trailing 12-month EBITDAX stands at 1.3x. Our long-term debt at the end of the quarter totaled about $1.3 billion with $1.1 billion of that being an unsecured term debt with the earliest maturity in 2019. Regarding our secured credit facility, I'll point you to Slide 7. The borrowing base currently stands at $1.55 billion and our bank commitment amount remains at $1 billion. At the end of the quarter, we had $228 million drawn, leaving $772 million of undrawn commitments. A summary of our current hedge position is included in the appendix to the flight deck and detailed hedging information is included in our Form 10-Q, which was filed earlier this morning. So with that, I'll turn over the call over to Jay.

Thank you, Wade. I'll begin my remarks on Slide 9 -- Production for the third quarter was 57 BCF equivalent, an increase of approximately 13% from the second quarter. The majority of that growth was driven by our Eagle Ford Shale program. I'd also like to note that our product mix for the quarter shifted to 55% gas. And as we continue to deploy capital in oily and rich gas programs, we're on track to meet our target of 50:50 liquids to gas production ratio in 2014. Moving to Slide 10, I'd like to talk about our operated Eagle Ford Shale program. This program has clearly been a large driver of production growth for the company over the past year, with quarterly production volumes increased by 90% from the third quarter of 2011. As for sequential growth from the second quarter, our operative program grew by 18% to an average of 243 million cubic feet equivalent per day for the quarter. Our ability to grow production during the quarter was largely driven by a step change in the buildout of our gathering system in the operated Eagle Ford program. During the quarter, 5 of the 6 tank batteries that we anticipated installing in the Galvan area during 2012 were installed in operation. As we mentioned before, our program for this year was back-end weighted with approximately 60% of our well completions occurring -- expected to occur in the second half. During the third quarter, we completed 24 wells compared to the 30 wells we completed in the entire first half of the year. For the full year, we expect the drilling complete about 74 wells and we'll have approximately 20 wells waiting on completion at year end. At the end of third quarter, we dropped 1 of our rigs in…

Thanks, Jay. Before turning the call over for your questions, I would like to sum up a few key points from the quarter. First, we had a great quarter on the production front, with quarterly production hitting a record of 57 BCF equivalent, and our 2 largest programs nearly doubling production volumes from the third quarter of last year. Second, we've installed 5 of the 6 tank batteries in our operated Eagle Ford program and expect the 6th battery to be installed by year end. Third, we have increased our full year production guidance the midpoint of 217 BCF equivalent implying a 28% production growth for this year. Finally, our balance sheet and financial position remains strong with the capacity to fund our key programs going forward. I'll now turn the call over to address your questions.

[Operator Instructions] Our first question comes from the line of Welles Fitzpatrick with Johnson Rice. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: On the Eagle Ford, obviously exiting at 5 rigs, but you talked about bumping up against capacity in 4Q and then obviously, get a little bit more in '13. Do you guys have, and I know you'll have the full plan in late December, but do you have an idea of whether you want to be running 4 or 5 to be able to kind of keep up with that ramp? And if you go down to 4, I mean, would we expect kind of $120 million, $140 million of savings from that rig drop?

This is Jay. And Welles, we haven't released yet. We're still working it. My gut feel is we're probably going to need to run 5 rigs next year. There may be a portion of the year where we can cut it up a little bit. But I think it's is probably a 5-rig program in order to keep up. If you remember, there's a very large increase in our downstream capacity. That happens in midyear. Where are downstream capacity goes from -- right now it's about 268, it goes to 382 in midyear next year. So we've got to get ready for that and make sure that we can make our ship-per-pay volumes. So I think right now, we're thinking, it's probably a 5-rig program. Our drilling is getting more efficient. One of the things I didn't -- I should have mentioned earlier was, we just drilled the Galvan well in less than 13 days. So we can -- we're getting more efficient in our activity. Five rigs will probably get us where we thought six rigs would've been a year ago. But I think it's probably going to be a 5-rig program. We are going to look at our capital program overall, though. Tony wants us to make sure disciplined about this. We are going to try get back closer to our cash flow next year, as we've said repeatedly. And we are going to try to flatten our -- the growth in our capital program. So we'll be looking at all of the capital programs of the company. We've got to make room for some of the Permian here, so you can probably anticipate that we'll trim rig count a little bit in some areas. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: Okay, and on the Permian, is it safe to assume that 10,000 plus acres that you added is in the Leonard and not on the New Mexico side?

That's -- that would be a good assumption, yes. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: Okay, and then one last one, kind of a Hail Mary. Other operators are beginning to talk about Nevada. Do you guys have an exploration program or plan for one in '13? And if so, when do you think you'll talk about it?

It is a Hail Mary.

We're not ruling out the prospectivity of running out of acreage at this point, certainly. But at this point, I don't have any comment on what our program would be in '13 for Nevada, or really any comment about, in general, what our exploration programs are. At this point, there's just nothing material to say. Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division: That's perfect. Congrats on the good quarter.

And your next question comes from the line of Brad Pattarozzi with Tudor, Pickering and Holt Brad Pattarozzi - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I'm thinking about 2013 plans. It's still a little early, as you say, but in terms of ramping activity in the Permian, if you're going to maintain activity in the Eagle Ford the 5 rigs, where would you think about slowing down activity to? We all think [ph] capital into the Permian?

This is Javan again. Well -- essentially, all our acreage in the Bakken, and all our acreage in the Granite Wash is HPP at this point. So we have opportunities there. Again, with increasing efficiencies in the Bakken and we can moderate our pace in the Granite Wash. I will also note that this year, of course, we're not going to be drilling any Haynesville wells which we did have some spin in the Haynesville last year, which we will not have in 2013. So we add a little bit of room there as well. So in fact, we don't have to cut our rig count much in order to support our program in the Permian. And I would say at this point, in the Permian, we're pretty confident in our Mississippian position. We haven't decisioned our shale program yet, and we may very well go into the year without budgeting a lot for that program. And then assuming success, add some later in the year if we need to. Brad Pattarozzi - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And thinking about the Permian again, it's still early, but in terms of giving more detail in terms of well results in the Leonard or Mississippian, is that going to be coming with 2013 plans in December? Or is that more of a 2013 timeframe, in terms of getting more details on well results?

Well, Mississippi, and I think we've been very transparent about our well results. And I don't think you should anticipate getting a lot more than that. In the Leonard, what we've said is we have 4 wells drilled and we're in various stages of flowing back a completion. I don't think I we'll have a definitive statement about whether all those wells -- whether we think we have a program or not until probably sometime in the first quarter. Brad Pattarozzi - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And staying with the Permian for a second. Capacity -- take away capacity in the Permian, is that something to worry about now? Or is that something you need to think about more into mid-to-late-2013 and 2014?

Well, we're not particularly concerned about it right now. The area that we're in there -- we're tracking the oil. It's not that much of an issue. The gas system up there is getting built out. We don't make that much gas. So it's not a huge issue. We are working it. In the Shale program, we have a -- I think we have a pretty solid plan there, we'll work through that. Again, that's program is basically contingent on success. So we're not getting too worried yet. I think we have a pretty good plan. It's a lot simpler, obviously than in Eagle Ford system that we had to build out. So we'll see. We'll see. But I think we're in pretty good shape. Brad Pattarozzi - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, great. And the last for me, moving now to the Bakken. What are you seeing from the current well cost and service cost and also differentials?

Well, this is Javan again. Oil differentials had been moving a lot. And obviously, have moved from a positive number to a negative number just in the last month. Last number I saw was minus 10. I saw that actually in our analyst report yesterday. And so I guess it's moving pretty quickly. So we've moved from what was essentially a $90 world and a positive differential to an $80 world and a negative differential in a month. So obviously, that's negative. On the cost side, we're probably down about 5% from the peak at this point. Continue to see opportunities. We've had some rig potential -- rig cost reductions as we renew rigs. Although, I kind of think that will go away here as people firm up the plans for next year. And then we've also seen some cost reduction on the frac side. And that's where most of our cost savings is coming from, is on pumping services. Rig count up there is still lower than it was a year ago. And I think people are generally consolidating into more efficient pad-drilling rigs. And there'll be quite a bit of competition, I think, for those -- for the good -- for the better rigs. And so I think the rig numbers are likely to firm up a little bit. But in general, if you say 5%, it's probably a reasonable number.

And your next question comes from the line of Pearce Hammond with Simmons & Company. Pearce W. Hammond - Simmons & Company International, Research Division: Just one quick question on realizations out of the Eagle Ford. How are you seeing those trending and some -- are you seeing some opportunity to improve those over the course of the next year, as far as the differentials?

Well, in general, yes, I understand. I think if you look at NGL realizations quarter-over-quarter, they were down a little bit of a percentage of what we get from NGL. Barrel actually went up a little bit. So they were -- I think that net, they were down slightly. In general, we think NGL realization will be up some over the next few quarters. On the oil side, I think they're pretty consistent with what we've been seeing. We always have been -- we have a gravity deduction there which in the end results in us having somewhat of a discount even the WTI. Although we do benefit from Louisiana prices being higher, I don't think we are anticipating any significant change in those. We will see some benefit when we start pipelining our oil in late year, probably in December this year. We'll probably see about a $3 or $4 barrel gain on the transportation side of the well site, which will end up in our net back. So that's the one thing I would say should get a little bit better.

And your next question comes from the line of Rudy Hokanson with Barrington Research.

A question on the tank batteries. Has that become an issue that's resolved in terms of timing for what you need? Or was it just that you were able to complete 5 of them earlier than you had expected, but going forward, if you're going to need more, there's still a delay in the system?

At this point, we don't think we need any more until next summer some time. And we're working on other issues, compression, pipeline. Really, the big focus this quarter is getting our oil system and our condensate system hooked up. We will see some production interruption during the quarter associated with doing some tie-ins and slug catchers and some things we need on the liquid side. So I think it will continue, every month, every month, every week, every quarter, we're doing infrastructure additions. At this point, we have the big centralized tank battery stuff mostly behind us for this year. And really, the next bottleneck for us is probably our downstream wet gas takeaway capacity, which is, right now, is 268. And then we get an increase in that in '13. So I think it's -- we've grown production 90% in the last 4 quarters. And sometimes it's a little lumpy due to things that happen in the field. But in a general sense, we're growing pretty fast, and I don't see a lot of front of us right now that keeps us from continuing to grow. So we continue to manage those, we'll try to guide each quarter as best we can. But I think it's pretty obvious, we're on a pretty significant growth trend here and it's just a matter of when it occurs, not if.

And your next question comes from the line of Jeb Bachmann with Howard Weil.

Just had a quick question on the Eagle Ford. I noticed that on the non-op acreage, again, the production versus kind of what Anadarko is talking about is -- I don't want to say blown out, but it's increased again similar to the first quarter. I just wonder if you guys feel that you've got a better handle, I guess? Then, Jay, you talked about early this year, you guys needed to do a better job in getting that forecast? Just kind of get your thoughts on that.

This is Wade, I'll say something first and Jay can add a few if he'd like. I'd say if you remember, if you're looking at the Slide 11, you went back to last quarter and remembered my remarks, if you added back 1.4000 [ph] barrels a day -- I think that's the number I said from an out-of-period standpoint, if you added that back to the second quarter, and then looked at the growth this quarter, it's about 28%, I think. And I noticed Anadarko earlier this week said that their whole Eagle Ford position grew 23%. And that's not an apples to apples as we've discussed in the past depending on which wells come online. We have different percentages in the different wells, but that's pretty close. It's not going to be perfect. I'm not trying to say that our percentage is going to be that close to theirs every quarter. But I think it's getting a lot better, I guess. That's the way I would characterize it.

Okay, great. And then last one for me is just, Jay, just on the timing, you said 2013 for the wet gas takeaway, what point in 2013 should we look for that?

Well, we have some increased takeaway in January, about 30 million a day. And then there's another -- I think -- let me just give you the actual numbers. 268 right now, it goes to 299 in the first quarter. We won't -- again, we need to be careful with all those numbers because we're not going to be producing -- 299 implies a net production of something like well over 300 and it'll take some time to get to those numbers after we have this capacity. But -- so we get to 299 capacity in the first quarter and then it jumps to 382 in the third quarter, which would imply net production rate well above -- above 400 if we have a well capacity to do it. So what we're going to be doing is building into those rates and trying to get our wells completed in a manner such that we can get as close to that as we can. There's a lot of other things out there. As we get additional capacity, then we'll run into other bottlenecks. So what I don't want people to do is just take this numbers and assume we're going to produce that every day because that's not going to happen. These are essentially head top-end numbers. But I think what it tells you is "Hey, we're going to have quite a bit of capacity coming and some real room to run." We're going to grow a lot next year. Again, it may be a little lumpy, quarter-to-quarter, but by the time we get to year end next year, we're going to be producing a bunch of production out of this field. So an exciting year coming.

And, Jay, you're still -- you guys are still on target to get to 300 or around 300 by the end of this year?

Well, again, that's essentially the most we can make on any given day. So the actual number is going to be lower than that. But yes, I think we're on track to essentially start bumping up against our wet gas capacity by the year end.

And your final question comes from the line of David Tameron with Wells Fargo.

A couple of questions, in the Eagle Ford, Jay, once you get past this -- this next leg of infrastructure additions, do you need -- when will you need -- what are the bottlenecks and when will you need another chunk of infrastructure to take the next growth step, if you will?

Well, David, it's kind of a continuous process from here on out. We -- we'll be adding compression consistently as we go forward. As Wade said, we haven't had to add as much as we thought we would so far. But we are -- we do anticipate adding a number of compression to get our well head pressures down. And that kind of is going to be an ongoing process. In terms of major tank battery additions, right now, it's probably going to be next summer some time, July, August, maybe even September, before we really need to have those in place. To get to that next leg. Again, we don't have a -- the big downstream capacity addition until July. So we don't want to get everything in place too early. And then depending on how our completions go. So I think that we got to get a lot of liquid out of the line. There's a whole bunch of stuff that's just going on continuously. Right now, the real focus on the field is to get our oil transportation stuff hooked up and going so we can get out of trucking business. So that's really what the guys in the field are focusing on in order to improve our operations, produce our cost, improve our net backs, is to get our oil in the pipe. So that's the first thing we need to do, and that's this quarter. There will be some production interruptions this quarter associated with that. We try to build our guidance around the idea that we probably will have some interruptions. And also, around the fact that we do have some limit on how much downstream gas we can make. So I hope we've accommodated all that in our guidance.

Okay. And on the trucking piece -- and maybe you've mentioned this but I missed it, but any estimate on what that will get you extra, what that helps in the net back, how much actually per barrel?

Yes, it should be $3 to $4 a barrel on what we can truck. Now we're not around to what we can ship in the pipeline. We didn't commit quite -- to a quite enough capacity to haul -- for all our oil, but it's going to be a good, probably 80% of it is going to end up on pipe. And it should be about $3 to $4 improvement on our net back.

Okay, and then just, well costs you talked about on the Bakken, can you say where they're tracking right now on the Eagle Ford?

Yes, we're about 10% below where we were -- we put out a pretty extensive set of numbers, I think February, March this year of 2012. And if you take those numbers and say we're 10% below that right now, that's probably real accurate.

Okay, and is that -- and just going forward, is that efficiencies and already some service cost built into that or would you anticipate that? I mean, that 10%, is that going to stay flattish for '13 or maybe a little bit of improvement or how...

I think it will improve some. We are spending some of that on some additional frac stages. But I think we will continue to see costs come down in 2013 by some amount. I just can't say enough good things. The guys down there have really done a terrific job. And the drilling side has really gone well. I mentioned the fact that we just completed the Galvan well in 13 days. And I think the first well we drilled in that program was 40-some days in the Galvan area. So our efficiencies are improving, our pad drilling. We're going to be moving to swarf [ph] drilling, which again, we'll probably have more downtime on our producing wells in some periods, but it's going to improve our efficiencies again there as we get in to drill our infill wells from the better parts of the field. We'll get into that here shortly in the next few months. A lot of things are driving more and more efficiencies into play and I think our costs will be lower next year.

Okay, and then last question. In the Bakken, can you just talk about what -- I know Raven and Borden, McKenzie, Williams Counties and then Gooseneck -- can you talk about -- are you seeing any material differences in the EURs in the production rates coming from Gooseneck versus the other 2 areas?

Well, Gooseneck EURs are probably 3 quarters of the EURs we see in the other areas. Again, it's much shallower. And our well costs are probably $1.5 million lower in Gooseneck than they are in the other areas. So from an economic standpoint -- the other comment I'll make, and you may -- guys may have seen the announcement that we are -- we have gotten some of our gathering systems for the divided county area going. So we're going to be able to net back higher net back there on -- and be able to sell our gas starting next year. So, again, improving our economies in some of the Gooseneck area. So I think all of it looks pretty good. And we're excited about it. It's largely HPP at this point. So we have a lot of control in what we do. We've moved the pad drilling. We're getting more efficient so we can drill more wells with the rigs we have. And I think the guys up there are doing a terrific job.

At this time, I would like to turn the call over to Tony Best for closing remarks.

Thank you all for joining our call this morning, and for your continued interest in SM Energy. We'll talk to you again next quarter. Thank you.

And this concludes today's conference. You may now disconnect.